Interface for deploying wireline tools with non-electric string

ABSTRACT

Embodiments of the present invention generally relate to a method and/or apparatus for deploying wireline tools with a non-electric string. In one embodiment, a method of determining a free point of a tubular string stuck in a wellbore includes deploying a tool string in the stuck tubular with a non-electric string. The free point assembly includes a battery, a controller, and a free point tool. The method further includes activating the free point tool by the controller. The free point tool contacts an inner surface of the stuck tubular string. The method further includes applying a tensile force and/or torque to the stuck tubular string; and measuring a response of the tubular string with the free point tool.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to a method and/orapparatus for deploying wireline tools with a non-electric string.

2. Description of the Related Art

Wellbores are typically formed by drilling a hole into the earth throughuse of a drill bit disposed at the end of a drill string. Most commonly,the drill string is a series of threaded tubular members, such as steelpipe. Weight is applied to the drill string while the drill bit isrotated. Fluids are then circulated through a bore within the drillstring, through the drill bit, and then back up the annulus formedbetween the drill string and the surrounding wellbore. The circulationof fluid in this manner serves to clear the bottom of the hole ofcuttings, serves to cool the bit, and also serves to circulate thecuttings back up to the surface for retrieval and inspection.

With today's wells, it is not unusual for a wellbore to be completed inexcess of ten thousand feet. The upper portion of the wellbore is linedwith a string of surface casing, while intermediate portions of thewellbore may be lined with liner strings. The lowest portion of thewellbore remains open to the surrounding earth during drilling. As thewellbore is drilled to new depths, the drill string becomes increasinglylonger. Because the wells are often non-vertical or deviated, a somewhattortured path can be formed leading to the bottom of the wellbore wherenew drilling takes place. Because of the non-linear path through thewellbore, the drill string can become bound or other wise stuck in thewellbore as it moves axially or rotationally. In addition, the processof circulating fluids up the annulus within the earth formation cancause subterranean rock to cave into the bore and encase the drillstring. All drilling operations must be stopped and valuable rig timelost while the drill string is retrieved (a.k.a. fished).

Because of the length of the drill string and the difficulty inreleasing stuck portions, it is useful to know the point at which onetubular is stuck within another tubular or within a wellbore. The pointabove the stuck point is known as the “free point.” It is possible toestimate the free point from the surface. This is based upon theprinciple that the length of the tubular will increase linearly when atensile force within a given range is applied. The total length oftubular in the wellbore is known to the operator. In addition, variousmechanical properties of the tubulars, such as yield strength andthickness, are also known. The operator can then calculate a theoreticalextent of tubular elongation when a certain amount of tensile force isapplied. The theoretical length is based on the assumption that theapplied force is acting on the entire length of the tubular.

The known tensile force is next applied to the tubular. The actuallength of elongation of the tubular is then measured at the surface ofthe well. The actual length of elongation is compared with the totaltheoretical length of elongation. By comparing the measured elongationto the theoretical elongation, the operator can estimate the stickingpoint of the tubular. For example, if the measured elongation is fiftypercent of the theoretical elongation, then it is estimated that thetubular is stuck at a point that is approximately one half of the lengthof the tubular from the surface. Such knowledge makes it possible tolocate tools or other items above, adjacent, or below the point at whichthe tubular is expected to be stuck.

It is desirable for the operator to obtain a more precise determinationof the stuck point for a string of tubulars. To do this, the operatormay employ a tool known as a “free point tool”. The prior art includes avariety of free point tools and methods for ascertaining the point atwhich a tubular is stuck. One common technique involves the use of afree point tool that has either one or two anchors for attaching to theinner wall of the drill pipe. The tool is lowered down the bore of thedrill string with a run-in string, and attached at a point to one of thetubulars. The tool utilizes a pair of relatively movable sensor membersto determine if relative movement occurred. The tool is located withinthe tubular at a point where the stuck point is estimated. The tool isthen anchored to the tubular at each end of the free point tool, and aknown tensile force (or torsional force) is applied within the string.Typically, the force is applied from the surface.

If the portion of the tubular between the anchored ends of the freepoint tool is elongated when a tensile force is applied (or twisted whena torsional force is applied), it is known that at least a portion ofthe free point tool is above the sticking point. If the free point tooldoes not record any elongation when a tensile force is applied (ortwisting when a torsional force is applied), it is known that the freepoint tool is completely below the sticking point. The free point toolmay be incrementally relocated within the drill string, and the one ormore anchor members reattached to the drill string. By anchoring thefree point tool within the stuck tubular and measuring the response indifferent locations to a force applied at the surface, the location ofthe sticking point may be accurately determined.

Typically, the run-in string is wireline. Wireline is a cable havingelectrically conductive wires through which voltage may be supplied topower and control the tool. The wireline includes one or more conductivewires surrounded by an insulative jacket. The conductive wires supply avoltage signal to the tool from a voltage source at the surface.Typically, an operator at the surface controls the tool by varying thevoltage signal supplied to the tool. For example, the operator may applyand remove the voltage signal to cycle power on and off, adjust a levelof the voltage signal, or reverse a polarity of the voltage. The tool isdesigned to respond to these voltage changes in a predetermined manner.

A less expensive, non-electric support cable is commonly referred to asslickline. Because slickline has no conductive lines to supply power tothe attached tool, the types of the tools deployed on slickline aretypically non-electric tools, such as placement and retrieval tools,mandrels, etc. Recently, battery powered tools have recently beendeveloped for slickline operation. Operation of the battery poweredtools may be initiated by lowering a slip ring device down the slicklinethat comes in contact with a switching device on a top surface of thetools. Alternatively, operation of the tools may be initiated by atriggering device that generates a trigger signal, for example, basedupon wellbore pressure (BHP), wellbore temperature (BHT), and toolmovement. Regardless of the method of initiation, the absence ofelectrically conductive wires prevents conventional surface interventionused to control wireline tools, which typically limits tools deployed onslickline to simple tools requiring little or no control, such aslogging tools.

Accordingly, a need therefore exists for a free point tool that can bequickly run into a wellbore on a more economical basis.

SUMMARY OF THE INVENTION

Embodiments of the present invention generally relate to a method and/orapparatus for deploying wireline tools with a non-electric string. Inone embodiment, a method of determining a free point of a tubular stringstuck in a wellbore includes deploying a tool string in the stucktubular with a non-electric string. The free point assembly includes abattery, a controller, and a free point tool. The method furtherincludes activating the free point tool by the controller. The freepoint tool contacts an inner surface of the stuck tubular string. Themethod further includes applying a tensile force and/or torque to thestuck tubular string; and measuring a response of the tubular stringwith the free point tool.

In another embodiment, a tool string for determining a free point of atubular stuck in a wellbore, includes a longitudinal strain gage and/ora torsional strain gage; first and second anchors operable tolongitudinally and rotationally couple the strain gages to the stucktubular in an extended position; an electric motor operable to extendand/or retract the anchors; a battery; and a controller operable tosupply electricity from the battery to the motor. The tool string istubular.

In another embodiment, a method of flow testing multiple zones in awellbore includes lowering a tool string into the wellbore with anon-electric run-in string. The tool string includes a battery, acontroller, an inflatable packer or plug, and an electric pump. Themethod further includes operating the pump by the controller, therebyinflating the packer or plug and isolating a first zone from one or moreother zones; monitoring flow from the first zone; deflating the packeror plug; moving the tool string in the wellbore; operating the pump bythe controller, thereby inflating the packer or plug and isolating asecond zone from one or more other zones; and monitoring flow from thesecond zone, wherein the zones are monitored in one trip.

In another embodiment, tool string for use in a wellbore includes aninflatable packer or plug; an electric pump operable to inflate thepacker or plug; and a deflation tool operable to deflate the packer orplug in an open position. The deflation tool is repeatably operablebetween the open position and a closed position and the tool string istubular. The tool string further includes a battery; and a controlleroperable to supply electricity from the battery to the pump.

In another embodiment, method for setting a plug in a cased or linedwellbore, comprising acts of: deploying a tool string in the wellboreusing a non-electric string. The tool string includes a battery; acontroller; a setting tool coupled to the run-in string; an adaptersleeve, and a packer or plug comprising a packing element. The methodfurther includes actuating the setting tool by the controller. Thesetting tool exerts a force on the adapter sleeve which transfers theforce to the packer or plug, thereby expanding the packing element intoengagement with an inner surface of the casing or liner. The methodfurther includes separating the setting tool from the packer or plug.The adapter sleeve remains with the packer or plug.

In another embodiment, a tool string for use in a formation treatmentoperation includes a setting tool comprising a mandrel and a settingsleeve. The setting sleeve is longitudinally moveable relative to thesetting tool mandrel between a first position and a second position. Thetool string further includes an adapter kit including an adapter rod andan adapter sleeve. The adapter rod is longitudinally coupled to thesetting mandrel and releasably coupled to a plug mandrel. The adaptersleeve is configured so that when the setting sleeve is moved toward thesecond position the setting sleeve abuts the adapter sleeve. The toolstring further includes a packer or plug including the plug mandrel anda packing element. The packing element is disposed along an outersurface of the mandrel. The adapter sleeve is configured to transfer asetting force to the plug, thereby radially expanding the packingelement. The tool string is tubular.

In another embodiment, a tool string for use in wellbore includes awireline tool; a battery module; a controller module operable to supplyelectricity from the battery to the wireline tool; a bus extendingthrough the modules and operable to provide data and power communicationamong the modules; and a safety module operable to isolate thecontroller module from the wireline tool until the safety module detectsa condition indicative of the tool string being disposed in thewellbore. The tool string is tubular.

In another embodiment, a tool string for use in tubular string stuck ina wellbore includes a cutting tool operable to sever the tubular string;an anchor operable to longitudinally and rotationally couple the cuttingtool to the tubular string; a battery; and a controller operable tosupply electricity from the battery to the cutting tool. The tool stringis tubular.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentinvention can be understood in detail, a more particular description ofthe invention, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this invention and are therefore not to beconsidered limiting of its scope, for the invention may admit to otherequally effective embodiments.

FIG. 1 shows a cross-sectional view of a wellbore being drilled.

FIG. 2 illustrates a freepoint tool (FPT) deployed using an interface,according to one embodiment of the present invention. FIG. 2A is a sideview of a carrier sleeve. FIG. 2B is a section view of the angulardisplacement sensor taken along section line 2B-2B in FIG. 2. FIG. 2C isa schematic of the interface 200. FIG. 2D is a side view of a fieldjoint 290 for connection between modules of the interface. FIG. 2E is anend view of the male and female ends of the field joint.

FIG. 3 is a schematic of the controller module.

FIG. 4 is a schematic of the battery module.

FIG. 5 is a schematic of the power supply module. FIG. 5A is a circuitdiagram of the FP power supply.

FIG. 6 is a schematic of the safety module.

FIG. 7A illustrates another wireline tool, such as a cutting tool thatmay be deployed using the interface, according to an alternativeembodiment of the present invention. FIG. 7B is a cross-sectional viewof the cutting tool and FIG. 7C is an exploded view of the cutting tool.

FIGS. 8A and 8B illustrate another wireline tool, such as a radialcutting torch, which may be deployed using the interface, according toan alternative embodiment of the present invention.

FIG. 9 is a schematic of a logging tools (LT) module.

FIG. 10 illustrates another wireline tool string that may be deployedusing the interface, according to an alternative embodiment of thepresent invention. FIGS. 10A-10K illustrate an inflation tool suitablefor use with the tool string. FIG. 10L is a partial section of a plugsuitable for use with the tool string 1000. FIG. 10M is a cross sectionof the plug.

FIGS. 11 and 11A illustrate a side view and a top view, respectively, ofanother wireline tool, such as a perforating tool, that may be deployedusing the interface, according to an alternative embodiment of thepresent invention.

FIG. 12 illustrates another wireline tool, such as tool string 1200,that may be deployed using the interface 200, according to analternative embodiment of the present invention.

FIGS. 13A and 13B illustrate an interface, according to anotherembodiment of the present invention.

FIGS. 14A-E illustrate configurations 1400 a-e of the interface intendedfor specific operations.

FIG. 15A illustrates another wireline tool string that may be deployedusing one of the interfaces, according to an alternative embodiment ofthe present invention. FIG. 15B illustrates another wireline tool stringthat may be deployed using one of the interfaces, according to analternative embodiment of the present invention. FIG. 15C illustratesanother wireline tool string that may be deployed using one of theinterfaces, according to an alternative embodiment of the presentinvention.

DETAILED DESCRIPTION

FIG. 1 shows a cross-sectional view of a wellbore 15 being drilled. Adrilling rig 10 is disposed over an earth surface 12 to create thewellbore 15 into subterranean formations 14. While a land-based rig 10is shown, the drilling rig 10 may alternatively be a floating orsubmersible vessel located over a subsea wellbore. The drilling rig 10includes draw works having a crown block 20 mounted in an upper end of aderrick 18. The draw works also include a traveling block 22. Thetraveling block 22 is selectively connected to the upper end of a drillstring 30. The drill string 30 includes a plurality of joints orsections of tubulars, such as drill pipe, which are threaded end to end.Additional joints of pipe are attached to the drill string 30 as thewellbore 15 is drilled to greater depths.

The drill string 30 includes an inner bore 35 that receives circulateddrilling fluid during drilling operations. The drill string 30 has adrill bit 32 attached to the lower end. Weight is placed on the drillbit 32 through the drill string 30 so that the drill bit 32 may actagainst lower rock formations 33. At the same time, the drill string 30is rotated within the borehole 15. During the drilling process, drillingfluid, e.g., “mud,” is pumped into the bore 35 of the drill string 30.The mud flows through apertures in the drill bit 32 where it serves tocool and lubricate the drill bit, and carry formation cuttings producedduring the drilling operation. The mud travels back up an annulus 45around the drill string 30, and carries the suspended cuttings back tothe surface 12.

The wellbore 15 has been drilled to a first depth D1, and then to asecond depth D2. At the first depth D1, a string of casing 40 has beenplaced in the wellbore 15. The casing 40 serves to maintain theintegrity of the formed wellbore 15, and isolates the wellbore 15 fromany ground water or other fluids that may be in the formations 14surrounding an upper portion of the wellbore 15. The casing 40 extendsto the surface 12, and is fixed in place by a column of set cement 44.Below the first depth D1, no casing or liner has yet been set.

A cave-in of the walls of the wellbore 15 has occurred at a depth P. Thecave-in P has produced a circumstance where the drill string 30 can nolonger be rotated or longitudinally translated within the wellbore 15,and is otherwise stuck. As discussed above, it is desirable for theoperator to be able to locate the depth of point P. To this end, a freepoint tool string (FPT) 100 is run into the wellbore 15. The FPT 100 isrun into the wellbore 15 on a non-electric run-in string 150. The run-instring 150 may be a slickline (shown), a coiled tubing string, or acontinuous sucker rod (COROD) string. The FPT 100 and slickline 150 arelowered into the wellbore by unspooling the line from a spool 155. Thespool 155 is brought to the drilling location by a service truck (notshown). Unspooling of the line 150 into the wellbore 15 is aided bysheave wheels 152. At the same time, the traveling block 22 is used tosuspend the drill string 30. A rough estimate of the cave-in depth P maybe determined by applying torque and/or a tensile load and measuring theresulting torsional deflection and/or elongation of the drill string 30.

The FPT 100 operates to more accurately locate the cave-in P along thelength of the drill string 30 so that all of the free sections of drillpipe 30 above the stuck point P can be removed. Once all of the jointsof pipe above an assured free point F are removed, new equipment can berun into the bore 15 on a working string to unstick or free theremaining drill string. From there, drilling operations can be resumed.

FIG. 2 illustrates the FPT 100 deployed using an interface 200,according to one embodiment of the present invention. The FPT 100 istypically deployed using wireline. The interface 200 allows wirelineoperated tools, such as the FPT 100, to be deployed using non-electricrun-in strings by providing power to and control over the tools thatwould have otherwise been provided from the surface using the wireline.Although shown with the FPT 100, the interface 200 may be used with anywireline deployed tool.

The FPT 100 includes upper 210 a and lower 210 b anchor assemblies and asensor assembly 250. Each of the anchor assemblies 210 a,b is operableto longitudinally and rotationally couple the FPT 100 to the stuck drillstring 30, while the sensor assembly 250 measures the response of thedrill string 30 to a tensile load and/or torque applied to the drillstring 30 from the surface 12. Each of the anchor assemblies 210 a,b mayinclude a tubular housing 230, a tubular mandrel 214, two or more arms225, a biasing member 212, and an actuator 245. The mandrel 214 isdisposed within the housing 230 so that the mandrel may movelongitudinally relative to the housing. Each of the arms 225 is pivotedto the housing 230 and operably coupled to the mandrel 214 so thatlongitudinal movement of the mandrel rotates the arms about the pivotbetween an extended position and a retracted position. In the extendedposition, the arms 225 engage an inner surface of the drill string 30,thereby longitudinally and rotationally coupling the housing to thedrill string. The arms 225 may each include a tip made from a hardmaterial, such as tungsten carbide, to penetrate the inner surface ofthe drill string 30. Teeth 215, 220 may be formed in an outer surface ofthe mandrel and an inner surface of each of the arms to provide a rackand pinion engagement between the mandrel and the arms. The biasingmember, such as a spring 212, is disposed between a shoulder of thehousing 230 and a shoulder of the mandrel 214 so that the arms arebiased toward the extended position.

The mandrel 214 is operably coupled to the actuator, such as an electricmotor 245. Operation of the motor 245 longitudinally moves the mandrel,thereby rotating the arms 225 between the extended position and theretracted position. The electric motor 245 may be operably coupled tothe mandrel by a mechanical assembly 240, such as a ballscrew or a wormgear, which translates rotation from a shaft of the motor intolongitudinal motion of the mandrel. One or more limit switches 235 a, bmay be provided to shut-off the motor 245 when the arms 225 reach theretracted position, thereby preventing damage to the motor. The arms 225are configured to engage the drill string in the extended position at anangle, such as forty-five to sixty degrees, relative to a horizontalaxis so that the tips of the arms are driven into the inner surface ofthe drill string upon application of a tensile load to the drill stringand, in the event of failure of the motor, the FPT 100 may be retrievedto the surface even though the arms are in the extended position. Thespring facilitates removal of the FPT 100 when the motor has failed byallowing the arms to collapse inwardly should an obstruction beencountered while retrieving the FPT. Alternatively, the arms may beactuated into the retracted position by a shearable connection (notshown) which may be activated from the surface by applying a tensileforce to the slickline 150.

The sensor assembly 250 may include a longitudinal strain gage 265, suchas a linear voltage differential transformer (LVDT), for measuringlongitudinal deflection of the drill string 30 under a tensile loadapplied from the surface and/or a torsional strain gage, such as anangular deflection sensor (ADS) 270, for measuring torsional deflectionof the drill string under torque applied from the surface. The LVDT 265and ADS 270 are isolated from wellbore conditions by a housing 260. Thehousing 260 may be made from a metal or alloy, such as a high yieldstrength specialty alloy.

FIG. 2A is a side view of a carrier sleeve 275. The carrier sleeve 275surrounds the sensor assembly 250 and includes reset slots 277 a, b inwhich alignment pins 255 a, b are disposed. The reset slots 277 a, bserve to reset the pins 255 a, b both longitudinally and rotationallywhen the slickline 150 is pulled a minimal amount, such as one-halfinch, while the anchors 210 a, b are engaged to the drill string 30.FIG. 2B is a section view of the angular displacement sensor 270 takenalong section line 2B-2B in FIG. 2. The angular displacement sensor 270employs two sensor coils 284 a, b placed close to each other in paralleland connected by a bridge circuit. A magnet pole piece 282 acts throughthe housing 260 and modulates the inductance of the sensor coils 284 a,b, adjusting the voltage across the bridge circuit and being detected asan angular displacement.

In operation, the FPT 100 is run-in to the drill string to an estimateddepth P of the cave in. The anchors 210 a,b are set and a tensile loadis applied to the drill string 30 from the surface 12. As the drillstring 30 is placed in tension at the surface, the portion of the drillstring 30 above the sticking point P will be elongated. The amount ofelongation of the drill string 30 which is between the sticking point Pand the upper anchor arms 225 will be detected by the LVDT 265. If theupper anchor arms 225 were located at a point below the sticking pointP, there would be no elongation detected by the LVDT 265. If the loweranchor arms 225 were located at a point above the sticking point, theLVDT 265 would detect elongation of the entire portion of the drillstring 30 between the upper anchor arms 225 and the lower anchor arms225. By applying a known force at the surface to the drill string 30 andmeasuring the response of the LVDT 265, it can be determined if theanchor arms 225 of the FPT 100 are above, on either side, or below thesticking point P. In this manner, the location of the sticking pointP/free point F may be precisely located.

Similarly, as the drill string 30 is placed in torsion at the surface,the portion of the drill string 30 above the sticking point P will beangularly displaced. The amount of angular displacement of the drillstring 30 which is between the sticking point P and the upper anchorarms 225 will be detected by the ADS 270 in the dual sensor assembly 250of the FPT 100. If the upper anchor arms 225 were located at a pointbelow the sticking point P, there would be no angular displacementdetected by the ADS 270. If the lower anchor arms 225 were located at apoint above the sticking point, the ADS 270 would detect angulardisplacement of the entire portion of the drill string 30 between theupper anchor arms 225 and the lower anchor arms 225. By applying a knowntorsional force at the surface to the drill string 30 and measuring theresponse of the ADS 270, it can be determined if the anchor arms 225 ofthe FPT 100 are above, on either side, or below the sticking point P. Inthis manner, the location of the sticking point P/free point F may beprecisely located.

The FPT 100 may be powered with positive voltage from the interface 200(core positive relative to the armor). Negative voltage may be reservedfor explosive or other desired operations, a feature which enhances thesafe operation of the FPT 100. In addition, the anchor arms 225 may becommanded to open and close by pulsing the positive voltage supply (turnoff momentarily and turn back on) and the sensor assembly 250 may runoff a positive voltage supply only. The FPT 100 may be essentiallyturned off during negative voltage supply conditions.

A string shot (not shown) may also be deployed with the FPT 100. Becausethe FPT 100 is not fluid filled and does not include a pressureequalizer system there is no fluid communication between the tool andfluid in the wellbore. Because this communication is unnecessary, theFPT 100 is not as susceptible to damage from hydrostatic pressure causedby the ignition of a string shot explosion. A string shot includes anexplosive charge designed to loosen a connection between two tubulars ata certain location in a wellbore. In the case of a tubular string thatis stuck in the wellbore, a string shot is especially useful todisconnect a free portion of the tubular string from a stuck portion ofthe tubular string in the wellbore. For example, after determining alocation in a wellbore where a tubular string is stuck, the nearestconnection in the tubular string there above is necessarily unthreadedso that the portion of the tubular string which is free can be removedfrom the wellbore. Thereafter, additional remedial measures can be takento remove the particular joint of tubular that is stuck in the wellbore.

A string shot is typically a length of explosive material that is formedinto the shape of a rope and is run into the wellbore on an electricalwire. The string shot is designed to be located in a tubular adjacentthat connection to be unthreaded. After locating the string shotadjacent the connection, the tubular string is rotated from the surfaceof the well to place a predetermined amount of torque on the stringwhich is measurable but which is inadequate to cause any of theconnections in the string to become unthreaded. With this predeterminedamount of torque placed on the string, the string shot is ignited andthe explosive charge acts as a hammer force on the particular connectionbetween joints. If the string shot operates correctly, the explosionloosens the joints somewhat and the torque that is developed in thestring causes that particular connection to become unthreaded or brokenwhile all the other connections in the string of tubulars remain tight.

Alternatively, one or both of the anchor assemblies 210 a, b may bedeployed with the interface 200 without the sensor assembly 250.Additionally, one of the anchor assemblies 210 a,b and another wirelinetool, such as a perforation gun or a cutting tool 700, 800 may bedeployed with the interface 200.

FIG. 2C is a schematic of the interface 200. The interface 200 mayinclude a cable head 205, a controller module 300, a battery module 400,a power supply module 500, a crossover 206 or safety module 600, and alogging tool (LT) module 900. Each of the modules 300-600, 900 of theinterface 200 communicates data with the other modules and transmitspower to and/or receives power from the other modules via an inter-toolbus (ITB). The ITB includes a plurality of wires that extends througheach of the modules 300-600, 900 of the interface 200. As shown, the ITBincludes eight wires: a positive communications wire, a negativecommunications wire, a controller power wire, a logging tool (LT) powerwire, a battery wire, two wireline tool (FP) power wires, and a groundwire. The battery wire may be separated into a main controller circuit,a power supply circuit, and an unused circuit by breaks in the batterymodule and the power supply module. Additionally, the ITB may includeone or more additional ground wires. Alternatively, the ITB may includeany number of wires, such as two to ten.

FIG. 2D is a side view of a field joint 290 for connection betweenmodules 300-600, 900 of the interface 200. Each field joint 290 includesa male end 290 m and a female end 290 f. The female end 290 f includes atubular housing and a socket 290 s disposed in the housing and having aplurality of pins, such as ten (shown). Each wire of the ITB correspondsto a respective pin. The extra pins may not be used or may be used foradditional ground wires. The male end 290 m includes a tubular housingand a plug 290 p disposed in the housing and having a correspondingnumber of holes for receiving the pins. The male end 290 m furtherincludes a threaded coupling 290 n disposed around the housing andlongitudinally coupled thereto. The threaded coupling 290 n is free torotate about a longitudinal axis of the housing. The female end 290 fincludes corresponding threads 290 t formed on an inner surface of thehousing for engagement with the threaded coupling 290 n. The male endmay include one or more o-rings disposed in one or more grooves formedin an outer surface of the housing to seal against the inner surface ofthe female end housing.

FIG. 2E is an end view of the male 290 m and female 290 f ends of thefield joint 290. The female end 290 f includes a plurality, such asthree, keys 290 k formed in an inner surface of the housing. The maleend 290 m includes a corresponding number of slots 290 s formed in anouter surface of the housing. Mating of the keys 290 k with the slots290 g ensures alignment of the pins with the corresponding holes. Tomake up the field joint 290, the male end is inserted into the femaleend so that the keys are received by the corresponding grooves until thethreads of the coupling engage with the threads formed in the femalehousing. The coupling 290 n is then rotated which will longitudinallyadvance the male end 290 m into the female end 290 f, thereby insertingthe pins into the slots.

Each module of the interface 200, except the safety module 600 andcontroller module 300, may have a male end and a female end. Each moduleof the interface 200 is enclosed in a tubular housing made from a metalor alloy, such as steel, stainless steel, or a corrosion resistantspecialty alloy for severe applications. The end housings may be formedwith housings of the respective modules or they may be welded thereto.The end housings may be made from the same material as the modulehousings. The controller module 300 may have one of the male and femaleends at a second end and may simply have a threaded coupling at a firstend for connection to the cable head. Alternatively, the cablehead 205may be a separate module connected to the ITB. In this alternative, thecontroller module 300 would have male and female ends and the cableheadwould have one of the male and female ends. The safety module 600 andcrossover 206 may have one of the male and female ends at a first endand may simply have a coax connector, such as a Gearhardt pin (GO)connector, at a second end for connection to the upper anchor assembly210 a.

FIG. 3 is a schematic of the controller module 300. The controllermodule may include a main controller, pressure sensor, a temperaturesensor, a casing collar locator (CCL), a tension sensor, externalmemory, a controller power supply, a wireline tool (FP) interface, and apower switch and monitor. The CCL may be a passive tool that generatesan electrical pulse when passing variations in pipe wall, such as acollar of the drillstring 30 within the wellbore 15. The main controllermay include a processor, internal memory, an accelerometer, a real timeclock, an ITB interface, a USB interface, an analog to digital converter(ADC), and a digital sensor interface. The main controller communicateswith and directs the operation of the other modules of the interface 200via the ITB. The FP interface allows the main controller to providepower to, and control or to collect data from wireline tools, such asthe FPT 100. The pressure sensor is in fluid communication with thewellbore and in data communication with the main controller, therebyallowing the main controller to monitor wellbore pressure. Thetemperature sensor is in fluid communication with the wellbore and indata communication with the main controller, thereby allowing the maincontroller to monitor wellbore temperature.

The accelerometer is in data communication with the main controller,thereby allowing the main controller to detect acceleration of theinterface 200 along a longitudinal axis thereof. The CCL is in datacommunication with the main controller, thereby allowing the maincontroller to monitor depth of the interface 200 in the wellbore. Thetension sensor 314 may be located in the cablehead 205 and is in datacommunication with the main controller, thereby allowing the maincontroller to monitor tension in the slickline 150. The internal memorystores data from the sensors and pre-programmed instructions from thesurface 12. The external memory unit is in data communication with themain controller and provides additional storage capacity for loggingdata when the LT module 900 is used.

The USB interface allows for retrieval of stored data from the internalmemory and/or external memory when the interface 200 is retrieved at thesurface. The USB interface also provides for programming of theinterface 200 with run-time parameters before a logging operation orother intervention service activity, diagnostics, or installation offirmware upgrades. The USB interface may be accessible from an end ofthe controller module 300 proximate to the cablehead by removing thecablehead. The clock allows the main controller to timestamp acquireddata which may then be merged with surface collected time/depth datafile for correlation purposes. The controller power supply receiveselectricity from the battery module 400 via the ITB and outputs a powersignal, such as 12 VDC, to the controller power line of the ITB.

FIG. 4 is a schematic of the battery module 400. The battery module mayinclude a battery stack, a battery interface, a controller, and adepassivation load. The battery stack includes a plurality of batteries,such as lithium cells. For example, the battery stack may include aplurality, such as ten to twenty, DD lithium cells assembled in seriesin one or more staves (i.e., ten cells in a stave), such as a fiberglasstube. The controller includes a processor, memory, and an ITB interface.The battery interface may include sensors for monitoring charge of thebattery stack, such as a voltage sensor, a current sensor, and aconsumption monitor. The controller is in data communication with thebattery interface for monitoring performance of the battery. Theconsumption monitor may provide a real time estimate of the remainingcharge in the battery stack so that a surface operator may know if thebattery stack is suitable for performing an intended job or ifreplacement is needed. The temperature gage is in communication with thebattery stack and in data communication with the battery controller,thereby allowing the battery controller to monitor the temperature ofthe battery stack.

The battery interface receives electricity from the battery stack andoutputs a first signal to the controller module via the ITB. The batteryinterface also outputs a second signal to the power supply module to theITB. A relay is disposed in the second signal line. The relay allows themain controller (via the ITB and the battery controller) to control whenelectricity to the power supply is provided. The electricity to thecontroller module may be unconditionally provided (or always on). Thedepassivation load allows for quick turn-on of the battery stack tosupply power at rated discharge rate. The battery module may alsoinclude a vent in the housing that may be actuated on the surfacewithout dismantling any component of the interface.

FIG. 5 is a schematic of the power supply module 500. The power supplymodule 500 may include a controller, a logging tool (LT) power supplyand a wireline tool (FP) power supply. The power supply module receiveselectricity from the battery module 400 via the ITB and outputs a firstelectric signal to the LT power line of the ITB and a second electricsignal to the FP power out line of the ITB. The controller may include aprocessor and an ITB interface. The controller is in data communicationwith the LT power supply and the FP power supply. The LT power supplymay be a simple fixed voltage, such as 100 VDC, power supply. The FPpower supply may be an adjustable voltage and current power supply andinclude a DC/DC switcher, a low pass filter, a monitoring and faultdetection unit, and a polarity switching relay. The main controller mayset the output voltage or current of the FP power supply via the ITB andthe power supply controller. The output line of the FP may include arelay in communication with the power supply controller. The powersupply controller may also switch on or off the LT power supply andmonitor performance thereof.

The FP power supply may be adjustable over a wide range, such as 50 to130 VDC in voltage control mode or 0 to 1.5 A in current control mode.Since the polarity may be reversible, the range may be increased to −50to −130 VDC and +50 to +130 VDC and 1.5 A to −1.5 A. This allowsflexibility for operating various wireline tools with the interface atdifferent voltages so multiple wireline tools may be deployed with theinterface and operated at different times. For example, an inflationtool 1000 a may operate at +130 VDC, the cutting tool 700 at +130 VDC, aradial cutting torch 800 at 1-1.5 A, the FPT at +75 VDC, and aperforating gun at −60 VDC. The main controller may instruct the FPpower supply to supply the operating voltage/current of a given wirelinetool according to a predetermined power control sequence in order tocontrol different functions of the tool. For example, given the FPT 100,a first power control sequence may instruct the FPT to set the anchorassemblies 210 a,b and a second power control sequence may instruct theFPT to retract the anchor assemblies. Data may be transmitted along thecoax wireline as power is also being transmitted along the coax wirelinebetween the interface and the wireline tools using any multiplexingtechnique.

FIG. 5A is a circuit diagram of the FP power supply. The DC/DC switchermay be a forward mode inverter. The DC/DC switcher may include zerovoltage transistor switching on primary transistors and be operated in apull-pull arrangement. The primary transistors may be operated at a50/50 duty cycle to allow free running. The DC/DC switcher may operateat high frequency to reduce size requirements for the transformer andallow resonant operation. Secondary regulation may be achieved bypulse-width modulation. The DC/DC switcher may include synchronousoutput rectification and include a micro-controller.

Alternatively, the LT power supply may be replaced by an adjustablepower supply with a power sharing circuit between the LT and FP powersupplies. This alternative would allow for a doubling of the outputpower capability for wireline tools when power for the logging tools isnot required. When power for the LT tools is required, the adjustable LTpower supply would simply be switched to the LT line of the ITB andoperated as a fixed voltage supply.

Alternatively, the controller power supply may be located in the powersupply module instead.

FIG. 6 is a schematic of the safety module 600. The safety module 600may include a controller, an interlock, a pressure switch, a temperatureswitch, a controller relay, an RF barrier, and a crossover. As discussedabove, the safety module includes a field joint for connection to othermodules of the interface 200 at a first end and a coax (i.e., GO pin)connector at a second end for connection to wireline tools. The safetymodule maintains a break in the FP power connection between theinterface 200 and the wireline tools until certain conditions aresatisfied so that wireline tools are not unintentionally operated at thesurface. The crossover 206 may be used instead of the safety module 600for wireline tools which do not present a hazard to surface personnel ifthe wireline tool is unintentionally operated at the surface.

The controller includes a processor and an ITB interface. The controlleris also in data communication with the interlock, the controller relay,and a local power supply. The local power supply receives controllerpower and outputs a signal to the interlock board and a signal to thetemperature switch. The pressure and temperature switches aremechanically operated once a certain minimum pressure (i.e., 200 psi)and temperature (i.e., 100 F) are met. This ensures power is notsupplied to any wireline tools until the interface and the wirelinetools reach a minimum safe depth in the wellbore and are not still onthe surface. The controller relay is operable by the main controller viathe ITB and the safety controller once the main controller determinesthat the interface 200 has reached operational depth in the wellbore(discussed below).

The interlock may include a pressure sensor, a temperature sensor andcomparison circuits to electronically verify that the interface 200 hasreached the minimum safe depth. Additionally, the interlock minimums maybe higher than the mechanical switch minimums. The interlock may furtherinclude a voltage sequence check to verify that the interface 200 isoperating properly before allowing power to the wireline tools.

In operation, the main controller is programmed at the surface toperform an operation with one or more wireline tools and/or one or morelogging tools. For example, the interface 200 may be assembled with theFPT 100. The interface and FPT are run into the wellbore. The maincontroller monitors for a trigger event. The trigger event may be apredetermined time, a temperature, a pressure, a number of casingcollars counted, a change in tension of the slickline, and/or anacceleration of the interface 200 (i.e., caused by jerking the slicklinefrom the surface). Alternatively, as previously described, the triggerevent may be generated by lowering a slip ring device (not shown) downthe slickline 150 to contact a switch (not shown) on the cablehead.

In response to detecting the trigger event, the main controllerinstructs the battery controller to close the relay in the power supplyoutput line and instructs the power supply controller to close the relayand supply a predetermined voltage from the FP power supply and toactivate the LT power supply (if the LT module 900 is present). If achemical cutter or RCT were included with the FPT, the main controllermay instruct the safety sub to close the relay (the pressure andtemperature switches automatically closed when wellbore conditions weredetected). The main controller instructs the LT power supply to outputthe first voltage sequence to set the anchor assemblies. The surface mayverify setting of the anchor assemblies by releasing the wireline. Thismay also provide a signal to the main controller that the surface isready to begin the freepoint test. Alternatively, the main controllermay just wait for a predetermined time.

The main controller may then continue supplying power to the FPT whilesurface personnel exert tension/torque on the drill string while the FPinterface receives data transmitted by the LVDT/ADS and records the datato memory. After the test is complete, the main controller instructs theFP power supply to output the second voltage control sequence, therebyretracting the anchor assemblies. The surface may indicate to the maincontroller by applying tension to the slickline. The surface would thenraise/lower the slickline to the next testing depth and the processwould then be repeated. The main controller may have a preprogrammednumber of tests or monitor for a trigger event from the surface todetermine when testing is concluded. Once testing is concluded, theinterface and the FPT may be retrieved to the surface and the data maybe downloaded from the main controller for analysis.

Additionally, one of the cutting tools 700, 800 may be included. Themain controller may analyze data received from the LVDT/ADS to detectthe free point F. When the freepoint is detected, the main controllermay operate the cutting tool to sever the drillstring. The maincontroller may carry the cutting operation out autonomously or firstsend a signal to the surface. Since no telemetry module is present, themain controller may use a crude mechanical signal, such as notretracting the anchor assemblies. The surface may verify that the anchorassemblies were not retracted due to mechanical failure by jerking onthe slickline a predetermined number of times, such as twice, quickly.The main controller may detect the response and confirm by retractingthe anchors. The surface could confirm by raising or lowering theinterface 200. Once the surface has confirmed the freepoint has beenlocated, the surface may send another signal to the main controller,i.e., jerking the slickline three times, to instruct the interface tooperate the cutting tool.

FIG. 7 illustrates another wireline tool, such as the cutting tool 700that may be deployed using the interface 200, according to analternative embodiment of the present invention. FIG. 7B is across-sectional view of the cutting tool 700 and FIG. 7C is an explodedview of the cutting tool 700. The cutting tool 700 further includes apump (not shown) and a motor (not shown). The pump may be the inflationtool 1000 a. The tool 700 has a body 702 which is hollow and generallytubular with conventional screw-threaded end connectors 704 and 706 forconnection to other components (not shown) of a downhole assembly. Theend connectors 704 and 706 are of a reduced diameter (compared to theoutside diameter of the longitudinally central body part 708 of the tool700), and together with three longitudinal flutes 710 on the centralbody part 708, allow the passage of fluids between the outside of thetool 700 and the interior of a tubular therearound (not shown).

The central body part 708 has three lands 712 defined between the threeflutes 710, each land 712 being formed with a respective recess 714 tohold a respective roller 716. Each of the recesses 714 has parallelsides and extends radially from the radially perforated tubular core 715of the tool 700 to the exterior of the respective land 712. Each of themutually identical rollers 716 is near-cylindrical and slightly barreledwith a single blade 705 formed thereon. Each of the rollers 716 ismounted by means of a bearing 718 (FIG. 7C) at each end of therespective roller for rotation about a respective rotation axis which isparallel to the longitudinal axis of the tool 700 and radially offsettherefrom at 120-degree mutual circumferential separations around thecentral body 708. The bearings 718 are formed as integral end members ofradially slidable pistons 720, one piston 720 being slidably sealedwithin each radially extended recess 714. The inner end of each piston720 (FIG. 7B) is exposed to the pressure of fluid within the hollow coreof the tool 700 by way of the radial perforations in the tubular core715.

By suitably pressurizing the core 715 of the tool 700 with the pump, thepistons 720 can be driven radially outwards with a controllable forcewhich is proportional to the pressurization, thereby forcing the rollers716 and blades 705 against the inner wall of a tubular. Conversely, whenthe pressurization of the core 715 of the tool 700 is reduced to belowthe ambient pressure immediately outside the tool 700, the pistons 720(together with the piston-mounted rollers 716) are allowed to retractradially back into their respective recesses 714. Although three rollers716 are shown, the cutting tool 700 may include one or more rollers 716.

In operation, the FPT 100, the interface 200, and the cutting tool 700may be run into the wellbore on the slickline 150. The slickline 150serves to retain the weight of the tools 100, 200, 700. After the FPT100 determines the sticking point in a manner described above, thecutting tool 700 may be positioned at the desired point of separation.Thereafter, power may be supplied by the interface 200 to actuate thepump to provide pressurized fluid to the cutting tool 700. The pressureforces the pistons 720 and the rollers 716 with their cutters 705against the interior of the tubular. Then, the cutting tool 700 isrotated in the tubular by the motor, thereby causing a groove of everincreasing depth to be formed around the inside of the tubular 750. Withadequate pressure and rotation, the tubular is separated into an upperand lower portions. Thereafter, the rollers 716 are retracted and thetools 100, 200, 700 may be removed from the wellbore. Additionally, thecutting tool 700 is capable of making a plurality of cuts at differentlocations along the tubular string during the same trip. For example, afirst cut may be made at the detected freepoint and then a second cutmay be made at a predetermined distance along the tubular toward thesurface from the first cut, such as thirty feet, as a redundant measureto ensure a second trip does not have to be made to free thedrillstring.

Alternatively, the interface 200 and cutting tool 700 may be deployed ina subsequent trip once the location of the FP is known.

FIGS. 8A and 8B illustrate another wireline tool, such as a radialcutting torch 800, which may be deployed using the interface 200,according to an alternative embodiment of the present invention. Theradial cutting torch 800 includes a connector subassembly 801, anignition subassembly 803 including members 804 and 805, an uppercombustible charge holding subassembly 831, a nozzle and intermediatecombustible charge holding subassembly 833 and a lower combustiblecharge holding subassembly 835. Members 804, 805, 831, 833, and 835 maybe formed of suitable metal or alloy.

The connector subassembly 801 has a lower end coupled to the ignitionsubassembly 803. The ignition subassembly comprise metal or alloymembers 804 and 805 screwed together with an electrode plug 808 coupledto member 804. The electrode 808 has a prong 809 which engages anelectrical conductor 810 supported by the lower end of member 804. Ametal or alloy spring 811 is disposed between the conductor 810 and anelectrically actuated igniter or squib 807 which is located in a smallaperture 883 extending through the lower end 805 e of member 805.Members 806 a, 806 b, and 806 c are O-ring seals. The members 808-811are electrically insulated to prevent a short. This ignition system maybe defined as an electric line firing system.

Member 831 has annular wall 832 with an enlarged opening 835 at itsupper end 836 with threads 837 leading to a smaller opening 839. Thelower end 841 member 831 has exterior threads 843 end O-ring seals 845.The nozzle subassembly 833 comprises an annular wall 847 with acylindrical opening 851 formed therethrough with interior threads 853and 855 at its upper and lower ends 857 and 859. The wall 847 comprisesa nozzle section 871 having a smaller outside diameter than the ends 847and 859. A plurality of rows of apertures 873 extend through the wallsection 871 and are circumferentially spaced therearound. Located on theinside of the wall section 871 is a hollow cylindrical shield 881 havingapertures 883 formed therethrough which are aligned with the apertures873. A thin metal sleeve 885 is secured around the outer wall 847 toprevent water from entering the apertures 873 and 883. Members 887 and889 are O-ring seals.

The lower subassembly 835 comprises an annular wall 890 having an upperend 891 with O-ring seals 892 and exterior threads 893. A cylindricalaperture 894 extends into the member 835 to a larger diameter opening814 having interior threads 813. A metal plug 815 with O-ring seals 817and exterior threads 819 is inserted into the opening 814 and screwedinto the lower end 821 of the member 835.

Also provided are a plurality of combustible pyrotechnic charges 878made of conventional material which is compressed into donut shapedpellets. The combustible material may be thermite or another mixture ofa metal or alloy and an oxide. Each of the charges has a cylindricalouter surface and a central aperture 878 a extending therethrough. Thecharges 878 are stacked on top of each other within the annular insidechamber portions 831 c, 833 c (inside of the carbon sleeve 881) and 835c with their apertures 878 a in alignment. Loosely packed combustiblematerial 880 preferably of the same material used in forming the charges878 is disposed with the apertures of the charges 878 such that eachcharge 878 is ignited from the loosely packed combustible material uponignition by the ignition means 807.

In assembling the components 803, 831, 833, and 835, the threads 893 ofend 890 of member 835 are screwed into threads 855 of the open end 859of member 833; the threads 843 of end 841 of member 831 are screwed tothe threads 853 of the open end 857 of member 833. During the assemblyprocess, the charges 878 are stacked into the chamber portions 835 c,833 c, and 831 c of members 835, 833, and 831. The threads 805 t of end805 e of assembled member 803 are screwed to the threads 837 of the openend 836 of the member 831. During the assembly process the charges 878are stacked on each other from the top end 815 t of the plug 815 and thematerial 880 placed in their apertures 878 a.

An electrically insulated electrical lead is coupled to the igniter 807by way of members 808-811 and an electrically insulated ground or returnlead 896 coupled to the igniter 807. An electrical power source 897 anda switch 898 are provided for applying electrical power to the igniter807 when the switch 898 is closed. The igniter 807 includes anelectrical resistor which generates heat when electrical current isapplied thereto. Thus when switch 898 is closed, current is applied tothe resistor of the igniter 807, which generates enough heat to ignitethe material 880 and hence the charges 878 to generate a very hightemperature flame with other hot combustion products which pass throughthe heat shield apertures 883 and the nozzle apertures 873 and throughthe thin sleeve 885 to cut the drill string 30.

An alternative embodiment of the radial cutting torch is discussed inU.S. Pat. No. 4,598,769, which is hereby incorporated by reference inits entirety. Alternatively, a jet cutter or chemical cutter may be usedinstead of the radial cutting torch. A jet cutter includes a circularshaped explosive charge that severs the tubular radially. A chemicalcutter includes a chemical (e.g., Bromine Trifluoride) that is forcedthrough a catalyst sub containing oil/steel wool mixture. The chemicalreacts with the oil and ignites the steel wool, thereby increasing thepressure in the tool 700. The increased pressure then pushes theactivated chemical through one or more radially displaced orifices whichdirects the activated chemical toward the inner diameter of the tubularto sever the tubular.

FIG. 9 is a schematic of a logging tool (LT) module 900. The LT modulemay include one or more of a cased hole flowmeter (CFT), a water holdupsensor (WHU), a cement bond log (CBL), a fluid density tool (FDT), agamma ray tool (GRT), and a caliper (CAL). Other logging tools not shownwhich may be included are array induction, photodensity, neutronporosity, compensated sonic, high-resolution shallow resistivity, duallaterolog, microlog/microlaterolog, hydraulic tension/compression, andultrasonic gas detector. The logging tools module may also include acontroller. The controller may include a processor and an ITB interface.The controller may in data communication with each of the logging tools.The controller may relay data from each of the logging tools to theexternal memory in the controller module. Each of the logging tools mayreceive LT power from the ITB. Additionally, each of the logging toolsmay have an individual controller and receive controller power from theITB. Alternatively, each of the logging tools may be a separate module,each having their own controller.

FIG. 10 illustrates another wireline tool string 1000 that may bedeployed using the interface 200, according to an alternative embodimentof the present invention. The tool string 1000 may include an inflationtool 1000 a, an adapter 1000 b, a check or one-way valve 1000 c, adeflation tool 1000 d, and an inflatable plug 1000 e. The inflation tool1000 a may connect the string 1000 to the adaptor 206 of the interface200 with a coax connection to provide electrical and mechanicalconnectivity. The adapter 1000 b may be used to couple the inflationtool 1000 a to the one-way valve 1000 c. Additionally, the adapter 1000b may be a cross-over having a fluid passage for fluid communicationbetween the inflation tool 1000 a and the inflatable plug 1000 e.

The inflation tool 1000 a may be a single or multi-stage downhole pumpcapable of drawing in wellbore fluid, filtering the fluids, andinjecting the filtered fluids into the inflatable plug 1000 e. Theinflation tool may be a positive displacement pump, such as areciprocating piston, or a turbomachine, such as a centrifugal, axialflow, or mixed flow pump. The inflation tool 1000 a may be operated viaelectricity supplied by the FP power supply.

FIGS. 10A-10K illustrate an inflation tool 1000 a suitable for use withthe tool string 1000. The inflation tool 1000 a may include a crossover1001, a plurality of screws 1002, a pressure balanced chamber housing1003, a conductor tube 1004, a pressure balance piston 1005, a fill portsub 1006, a controller housing 1007, a spring 1008, a pump housing 1009,a working fluid pump 1010, a pump washer 1011, a pump adaptor 1012, acontrol valve bulkhead 1013, a spring coupler 1014, a detent housing1015, a disc 1016, a control rod 1017, a plurality of heavy springs1018, a plurality of light springs 1019, a top bulkhead 1020, aplurality of plugs 1021, a drive piston 1022 a, a pump piston 1022 b, aplurality of ported hydraulic cylinders 1023, a middle bulkhead 1024, abottom bulkhead 1026, a controller 1027, an electric motor 1028, afilter support ring 1029, a vent tube 1030, a filter support tube 1031,a filter housing 1032, a vent crossover 1033, a plurality of shearscrews 1034, a directional valve 1035, a check valve assembly 1036, adrive shaft 1037, a bushing seal 1038, a cylinder housing 1039, a groundwire assembly 1041, a lead wire assembly 1042, a spring 1043, an outputtube 1044, a retaining ring 1045, a plurality of set screws 1046, aspring bushing 1047, a ring 1048, a vent housing 1049, a vent extension1050, a vent piston 1051, a socket sub 1052, a spring 1053, a filter1054, a spacer 1056, a crossover 1057, a ball 1060, a spring 1061, anozzle 1062, a washer 1065, a set screw 1066, a plurality of O-rings1067, a T-seal 1068, a seal stack 1069, and a wiper 1070. The checkvalve assembly 1036 may include a plurality of check valves 1080 a-d.Each check valve may include a check ball 1081, a spring 1082, and aplug 1083.

As shown, the inflation tool 1000 a may be an electro-hydraulic pump.The middle bulkhead 1024 fluidly isolates a working fluid portion of thepump 1000 a from a wellbore fluid portion of the pump. The working fluidportion is filled prior to insertion of the pump 1000 a in the wellbore15. The working fluid may be a clean liquid, such as oil. The workingfluid portion of the pump is a closed system. The electric motor 1028receives electricity from the FP power supply and drives the workingfluid pump 1010. The working fluid pump 1010 pressurizes the workingfluid which drives the drive piston 1022 a. The drive piston 1022 a isreciprocated by the directional valve 1035 alternately providing fluidcommunication between each longitudinal end of the drive piston 1022 aand the pressurized working fluid. The drive piston 1022 a islongitudinally coupled to the pump piston 1022 b.

The check valve assembly 1036 includes the inlet check valve 1080 a, band the outlet check valve 1080 c, d for each longitudinal end of thepump piston 1022 b. The inlet check valves are in fluid communicationwith an outlet of the filter 1054. Wellbore fluid is drawn in throughone or more inlet ports (see FIG. 10) of the filter 1054. Solidparticulates are filtered from the wellbore fluid as it passes throughthe filter. Filtered wellbore fluid is output from the filter to theinlet check valves. Pressurized filtered wellbore fluid is driven fromthe pump piston to the outlet check valves. The outlet check valves arein fluid communication with the vent tube 1030. Pressurized filteredwellbore fluid travels through the vent tube 1030 and the vent extension1050 to the crossover 1057. The pressurized filtered wellbore fluidcontinues through the string 1000 until it reaches the plug 1000 e.

The pressure balance piston 1005 maintains a working fluid reservoir atwellbore pressure. The pump 1000 a may also be temperature compensated.The vent piston 1051 allows for the pump 1000 a to operate in a closedsystem or in cross-flow.

A suitable one-way valve 1000 c is illustrated in FIG. 4 of U.S. patentapplication Ser. No. 12/030,154, filed Feb. 12, 2008, which is herebyincorporated by reference in its entirety. The one-way valve 1000 c isoperable to maintain inflation of the inflatable plug 1000 e. In thisrespect one-way valve 1000 c allows fluid to be pumped from theinflation tool 1000 a toward the inflatable plug 1000 e for inflationthereof, while preventing backflow of the pumped fluid from theinflatable plug 1000 e. The one-way valve 1000 c includes one or morevalve elements, such as flappers. Alternatively, a ball biased to engagea seat may be used instead of the flapper. Each flapper is biased towarda closed position by a respective spring. Each flapper is pivoted to ahousing by a respective pin. The housing may include one or moretubulars. Each of the tubulars may be connected by threaded connections.The dual valve elements provide for redundancy in the event one offailure of one of the valve elements. Alternatively, the one-way valvemay be integrated with the outlet of the inflation tool 1000 a, therebyeliminating the need of a separate valve sub connection. If theinflation tool 1000 a includes an integral check valve, then the one-wayvalve 1000 c may be omitted.

A suitable deflation tool, such as a pickup-unloader 1000 d, isillustrated in FIG. 5 of the '154 application. When operated by applyinga tensile force to the slickline 150 (picking up), the deflation tool1000 d relieves the fluid in the inflatable plug 1000 e. Application ofcompression force (slacking off) will close the deflation tool 1000 d.The deflation tool 1000 d includes a tubular mandrel having alongitudinal flow bore therethrough. A top sub is connected to themandrel and a seal, such as an O-ring, isolates the connection. The topsub connects to the check valve 1000 c. A tubular case assemblyincluding an upper case, a nipple, and a lower case is disposed aroundthe mandrel and longitudinally movable relative thereto. Seals, such asO-rings or other suitable seals, isolate the case assembly connections.A biasing member, such as a spring, is disposed between a ring whichabuts a nut longitudinally coupled to the mandrel and a longitudinal endof the nipple. The ring may also be secured with one or more set screws.The spring biases the deflation tool toward a closed position.

In the closed position, one or more ports, such as slots, formed throughthe upper case are isolated from one or more ports, such as slots,formed through the mandrel. A nozzle may be disposed in each of theupper case ports. Seals, such as o-rings, isolate the upper case portsfrom an exterior of the deflation tool and from the mandrel ports. Whenoperated to an open position, a tensile force exerted on the slickline150 pulls the mandrel flow ports into alignment with the upper caseports while overcoming the biasing the force of the spring until ashoulder of the mandrel engages a shoulder of the upper case. Thisallows the pressurized fluid stored in the inflated plug 1000 e to bedischarged into the wellbore, thereby deflating the plug. Slacking offof the wireline allows the spring to return the mandrel to the closedposition where the mandrel shoulder engages a longitudinal end of thenipple.

FIG. 10L is a partial section of a plug 1000 e suitable for use with thetool string 1000. FIG. 10M is a cross section of the plug 1000 e. Theplug 1000 e includes a packing element 1086. The packing element 1086may be inflated using wellbore fluids, or transported inflation fluids,via the inflation tool 1000 a. When the packing element 1086 is filledwith fluids, it expands and conforms to a shape and size of the casing.

The plug 1000 e may include a crossover housing, a crossover mandrel1087 a and a plug mandrel 1087 b. A bore 1090 is formed through a wallof the crossover housing. The crossover mandrel 1087 a defines a tubularbody having a bore 1088 a formed therethrough. The plug mandrel 1087 bdefines a tubular body which runs the length of the packing element1086. A bore 1088 b is defined within the plug mandrel 1087 b. Anannulus 1089 is defined between the outer surface of the plug mandrel1087 b and the surrounding packing element 1086. The annular region 1089of the packing element 1086 receives fluid from the bore 1090 when thepacking element 1086 is actuated. This serves as the mechanism forexpanding the packing element 1086 into a set position within thecasing. To expand the packing element 1086, fluid is injected by theinflation tool 1000 a, through bore of a top sub 1085, through the boreof the crossover mandrel 1087 a, through a port formed through a wall ofthe crossover mandrel, through the bore 1090, and into the annulus 1089of the packing element 1086. Fluid continues to flow downward throughthe plug 1000 e until it is blocked at a lower end by a nose 1098.

The packing element 1086 includes an elongated bladder 1091. The bladder1091 is disposed circumferentially around the plug mandrel 1087 b. Thebladder 1091 may be fabricated from a pliable material, such as apolymer, such as an elastomer. The bladder 1091 is connected at oppositeends to end connectors 1092 and 1093. The upper end connector 1092 maybe a fixed ring, meaning that the upper end of the packing element 1086is stationary with respect to the plug mandrel 1087 b. The lower endconnector 1093 is connected to a slidable sub 1095. The slidable sub1095, in turn, is movable along the plug mandrel 1087 b. This permitsthe bladder 1091 and other packing element parts to freely expandoutwardly in response to the injection of fluid into the annulus 1089between the plug mandrel 1087 b and the bladder 1091. Movement of thelower end connector 1093 upward along the plug mandrel 1087 b allows thepacking element 1086 to be inflated.

The packing element 1086 may further include an anchor portion 1096.Alternatively, an anchor may be formed as a separate component. Theanchor portion 1096 may be fabricated from a series of reinforcingstraps 1099 that are disposed around the bladder 1091. The straps 1099may be longitudinally oriented so as to extend at least a portion of thelength of or essentially the length of the packing element 1086. At thesame time, the straps 1099 are placed circumferentially around thebladder 1091 in a tightly overlapping fashion. The straps 1099 may befabricated from a metal or alloy. Alternatively, other materialssuitable for engaging the casing may be used, such as ceramic orhardened composite. The straps 1099 may be arranged to substantiallyoverlap one another in an array. A sufficient number of straps 1099 areused for the anchor portion 1096 to retain the bladder 1091 therein asthe anchor portion 1096 expands.

The metal straps 1099 are connected at opposite first and second ends.The strap ends may be connected by welding. The ends of the straps 1099are welded (or otherwise connected) to the upper 1092 and lower 1093 endconnectors, respectively. The anchor portion 1096 is not defined by theentire length of the straps 1099; rather, the anchor portion 1096represents only that portion of the straps 1099 intermediate the endconnectors 1092, 1093 that is exposed, and can directly engage thesurrounding casing. In this respect, a length of the straps 1099 may becovered by a sealing cover 1097.

The sealing cover 1097 is placed over the bladder 1091. The cover 1097is also placed over a selected length of the metal straps 1099 at oneend. Where a cover ring 1094 is employed, the sealing cover 1097 isplaced over the straps 1099 at the end opposite the cover ring 1094. Thesealing cover 1097 provides a fluid seal when the packing element 1086is expanded into contact with the surrounding casing. The sealing cover1097 may be fabricated from a pliable material, such as a polymer, suchas an elastomer, such as a blended nitrile base or a fluoroelastomer. Aninner surface of the cover 1097 may be bonded to the adjacent straps1099.

The sealing cover 1097 for the packing element 1086 may be uniform inthickness, both circumferentially and longitudinally. Alternatively, thesealing cover 1097 may have a non-uniform thickness. For example, thethickness of the sealing cover 1097 may be tapered so as to graduallyincrease in thickness as the cover 1097 approaches the anchor portion1096. In one aspect, the taper is cut along a constant angle, such asthree degrees. In another aspect, the thickness of the cover 1097 isvariable in accordance with an undulating design. The variable thicknesscover reduces the likelihood of folding within the bladder 1091 duringexpansion. This is because the variable thickness allows some sectionsof the cover 1097 to expand faster than other sections, causing theoverall exterior of the element 1086 to expand in unison.

The cover ring 1094 is optionally disposed at one end of the anchorportion 1096. The cover ring 1094 may be made from a pliable material,such as a polymer, such as an elastomer. The cover ring 1094 serves toretain the welded metal straps 1099 at one end of the anchor portion1096. The cover ring 1094 typically does not serve a sealing functionwith the surrounding casing. The length of the cover ring may be lessthan the outer diameter of the packing element's running diameter.

As the bladder 1091 is expanded, the exposed portion of straps 1099 thatdefine the anchor portion 1096 frictionally engages the surroundingcasing. Likewise, expansion of the bladder 1091 also expands the sealingcover portion 1097 into engagement with the surrounding casing. The plug1000 a is thus both frictionally and sealingly set within the casing.The minimum length of the anchor portion 1096 may be defined by amathematical formula. The anchor length may be based upon the formula oftwo point six three multiplied by the inside diameter of the casing. Themaximum length of the expanded anchor portion 1096 may be less thanfifty percent of the overall length of the packing element 1086 uponexpansion. In this regard, the anchor portion 1096 does not extendbeyond the center of the packing element 1086 after the packing elementis expanded.

The tool string 1000 may be used to isolate and flow test multiple zonesof a hydrocarbon bearing formation. The test may include a pressurebuildup and/or a pressure drawdown test. For example, the tool string1000 may be used to test three perforated zones. Initially, productionfrom all three zones may be measured to determine the total flow. Thetool string 1000 and the interface 200 may then be deployed into thewellbore such that the inflatable plug 1000 e is positioned between thefirst zone and the second zone, thereby isolating the first zone fromthe second and third zones.

Once the main controller detects the trigger event, the main controllerinstructs the FP power supply to operate the pump 1000 a, therebyexpanding the inflatable plug 1000 e. The current draw of the inflationtool 1000 a may be monitored by the main controller via the power switchand monitor to determine the extent of inflation. For example, thecurrent draw may be proportional to the pressure in the inflatable plug1000 a. The inflatable plug 1000 e is inflated until a predeterminedpressure is reached. The inflation pressure is maintained by the one-wayvalve 1000 c. Actuation of the inflatable plug 1000 e isolates the firstzone from the other two zones. In this respect, only the flow from thesecond and third zones is collected.

After flow of the second and third zones has occurred for apredetermined time, the inflatable plug 1000 e is deflated and moved toanother location. To deflate the plug 1000 e, the slickline 150 ispicked up to apply a tension force to the deflation tool 1000 c, in thiscase, the pickup unloader. The tension force causes the pickup unloader1000 c to open, thereby allowing deflation of the plug 1000 e.

After deflation, the plug 1000 e is moved to a location between thesecond zone and the third zone. The main controller may wait for apredetermined period of time or monitor for another trigger event. Theprocess of actuating the plug 1000 e is repeated to isolate the thirdzone from the remaining two zones. In this respect, only flow from thethird zone is collected. After the test is run, the plug 1000 e may bedeflated in a manner described above. From the flow data collected fromthe two tests and the total flow of all three zones, the flow of eachzone may be calculated. In this manner, flow testing of multiple zonesmay be performed in one trip.

The tool string 1000 may also include an instrumentation sub (notshown). The instrumentation sub may include sensors to monitor conditionof the tool string 1000. For example, the instrumentation sub mayinclude pressure and temperature sensors in communication with theinflation fluid path for monitoring performance of the inflation tool1000 a and/or the plug 1000 e. Additionally, the instrumentation sub mayinclude a sensor for determining whether the plug has set properly(i.e., by monitoring position of the slidable sub 1095). The tool string1000 may further include a second instrumentation sub disposed below theplug 1000 e so that it may measure the effect of testing one or morezones on the isolated zone(s). The instrumentation sub may be in datacommunication with the main controller.

FIGS. 11 and 11A illustrate a side view and a top view, respectively, ofanother wireline tool, such as a perforating tool 1100 that may bedeployed using the interface 200, according to an alternative embodimentof the present invention. The perforating tool 100 may include aperforating gun 1105, a ferrous sensor 1110, an anchor (not shown), andan electric motor (not shown). For example, the perforating tool 1100may be anchored by the inflation tool 1000, one of the anchor assemblies210 a,b, or the frac-plug 1225.

The ferrous sensor 1110 detects a location of the adjacent pipe 1130 bso as not to damage it. The ferrous sensor 1110 may be located togenerate a signal when a perforating gun 1105 is pointing in an oppositedirection of the adjacent pipe 130 b. The main controller may generate asignal to rotate the perforating gun 1105 while monitoring the signalgenerated by the ferrous sensor to determine a direction of theperforating gun 1105 with respect to the adjacent pipe 1130 b. The maincontroller may then generate a signal to fire the perforating gun 1105in response to determining the perforating gun 1105 is pointing awayfrom the adjacent pipe 1142.

In operation, the interface 200 and the perforating tool 1100 arelowered into the wellbore 15. The main controller detects the triggerevent. The main controller instructs the FP power supply to generate asignal to rotate the perforating tool 1118 while monitoring the signalgenerated by the ferrous sensor 1124. The main controller may theninstruct the FP power supply to generate a firing signal to fire theperforating gun 1110 in response to determining the perforating gun 1105is pointing away from the adjacent pipe 1130 b.

FIG. 12 illustrates another wireline tool, such as tool string 1200,that may be deployed using the interface 200, according to analternative embodiment of the present invention. The tool string 1200may include one or more perforation guns 1292 a-d, a setting tool 1205,an adapter kit 1215, and a frac plug 1225. Each perforation gun 1292 a-dincludes one or more perforation charges 1294 a-d and is independentlyfired using a select-fire firing head 1290 a-d.

The frac-plug 1225 may include a mandrel 1245, first and second slips1229 a,b, first and second slip cones 1230 a,b, a packing element 1240,first and second element cones 1235 a,b, first and second expansionrings 1234 a,b, and first and second expansion support rings 1232 a,b.The frac-plug assembly 1225 may be made from a drillable material, suchas a non-steel material. The mandrel 1245 and the cones 1230 a,b and1235 a,b may be made from a fiber reinforced composite. The compositematerial may be constructed of a polymer that is reinforced by acontinuous fiber such as glass, carbon, or aramid, for example. Thepolymer may be an epoxy blend, polyurethanes, or phenolics. The slips1229 a,b may be made from a non-steel metal or alloy, such as cast iron.The packing element 1240 may be made from a polymer, such as anelastomer.

The packing element 1240 is backed by the element cones 1235 a,b. Ano-ring 1251 (with an optional back-up ring) may be provided at theinterface between each of the expansion cones and the packing element1240. The expansion rings 1234 a,b are disposed about the mandrel 1245between the element cones 1235 a,b, and the expansion support rings 1232a,b. The expansion support rings 1232 a,b are each an annular memberhaving a first section of a first diameter that steps up to a secondsection of a second diameter. An interface or shoulder is thereforeformed between the two sections. Equally spaced longitudinal cuts arefabricated in the second section to create one or more fingers or wedgesthere-between. The number of cuts is determined by the size of theannulus to be sealed and the forces exerted on each expansion supportring 1232 a,b.

The wedges are angled outwardly from a center line or axis of eachexpansion support ring 1232 a,b at about 10 degrees to about 30 degrees.The angled wedges hinge radially outward as each expansion support ring1232 a,b moves longitudinally across the outer surface of eachrespective expansion ring 1234 a,b. The wedges then break or separatefrom the first section, and are extended radially to contact an innerdiameter of the surrounding casing 55 b. This radial extension allowsthe entire outer surface area of the wedges to contact the inner wall ofthe casing 55 b. Therefore, a greater amount of frictional force isgenerated against the surrounding tubular. The extended wedges thusgenerate a “brake” that prevents slippage of the frac plug assembly 1225relative to the casing 40.

The expansion rings 1234 a,b may be manufactured from a polymer, such aspolytetrafluoroethylene (PTFE). The second section of each expansionsupport ring 1232 a,b is disposed about a first section of therespective expansion ring 1234 a,b. The first section of each expansionring 1234 a,b is tapered corresponding to a complimentary angle of thewedges. A second section of each expansion ring 1234 a,b is also taperedto compliment a sloped surface of each respective element cone 1235 a,b.At high temperatures, the expansion rings 1234 a,b expand radiallyoutward from the mandrel 1245 and flow across the outer surface of themandrel 1245. The expansion rings 1234 a,b fill the voids createdbetween the cuts of the expansion support rings 1232 a,b, therebyproviding an effective seal.

The element cones 1235 a,b are each an annular member disposed about themandrel 1245 adjacent each end of the packing element 1240. Each of theelement cones 1235 a,b has a tapered first section and a substantiallyflat second section. The second section of each element cone 1235 a,babuts the substantially flat end of the packing element 1240. Eachtapered first section urges each respective expansion ring 1234 a,bradially outward from the mandrel 1245 as the frac plug assembly 1225 isset. As each expansion ring 1234 a,b progresses across each respectivetapered first section and expands under high temperature and/or pressureconditions, each expansion ring 1234 a,b creates a collapse load on arespective element cone 1235 a,b. This collapse load holds each of theelement cones 1235 a,b firmly against the mandrel 1245 and preventslongitudinal slippage of the frac plug assembly 1225 once the frac plugassembly 1225 has been set in the wellbore. The collapse load alsoprevents the element cones 1235 a,b and packing element 1240 fromrotating during a subsequent mill/drill through operation.

The packing element 1240 may have any number of configurations toeffectively seal an annulus within the wellbore. For example, thepacking element 1240 may include grooves, ridges, indentations, orprotrusions designed to allow the packing element 1240 to conform tovariations in the shape of the interior of a surrounding tubular (notshown). The packing element 1240, may be capable of withstanding hightemperatures, i.e., four hundred fifty degrees Fahrenheit, and highpressure differentials, i.e., fifteen thousand psi.

The mandrel 1245 is a tubular member having a central longitudinal boretherethrough. A plug 1247 may be disposed in the bore of the mandrel1245. The plug 1247 is a rod shaped member and includes one or moreO-rings 251 each disposed in a groove formed in an outer surface of theplug 1247. A back-up ring may also be disposed in each of the pluggrooves. Alternatively, the mandrel 1245 may be solid. The slips 1229a,b are each disposed about the mandrel 1245 adjacent a first end ofeach respective slip cone 1230 a,b. Each slip 1229 a,b includes atapered inner surface conforming to the first end of each respectiveslip cone 1230 a,b. An outer surface of each slip 1229 a,b, may includeat least one outwardly extending serration or edged tooth to engage aninner surface of a the casing 40 when the slips 1229 a,b are drivenradially outward from the mandrel 1245 due to longitudinal movementacross the first end of the slip cones 1230 a,b.

The slips 1229 a,b are each designed to fracture with radial stress.Each slip 1229 a,b typically includes at least one recessed groovemilled therein to fracture under stress allowing the slip 1229 a,b toexpand outward to engage an inner surface of the casing 40. For example,each of the slips 1229 a,b may include four sloped segments separated byequally spaced recessed grooves to contact the casing 40, which becomeevenly distributed about the outer surface of the mandrel 1245.

Each of the slip cones 1230 a,b is disposed about the mandrel 1245adjacent a respective expansion support ring 1232 a,b and is secured tothe mandrel 1245 by one or more shearable members 1249 c such as screwsor pins. The shearable members 1249 c may be fabricated from a drillablematerial, such as the same composite material as the mandrel 1245. Eachof the slip cones 1230 a,b has an undercut machined in an inner surfacethereof so that the cone 1230 a,b can be disposed about the firstsection of the respective expansion support ring 1232 a,b, and buttagainst the shoulder of the respective expansion support ring 1232 a,b.Each of the slips 1229 a,b travel about the tapered first end of therespective slip cone 1230 a,b, thereby expanding radially outward fromthe mandrel 1245 to engage the inner surface of the casing 40.

One or more setting rings 1227 a,b are each disposed about the mandrel1245 adjacent a first end of the first slip 1229 a. Each of the settingrings 1227 a,b is an annular member having a first end that is asubstantially flat surface. The first end of the first setting ring 1227a serves as a shoulder which abuts an adapter sleeve 1220. A supportring 1242 is disposed about the mandrel 1245 adjacent the first end ofthe first setting ring 1227 a. One or more pins 1249 b secure thesupport ring 1242 to the mandrel 1245. The support ring 1242 is anannular member and serves to longitudinally restrain the first settingring 1227 a.

The setting tool 1205 includes a mandrel 1207 and a setting sleeve 1209which is longitudinally movable relative to the mandrel 1207. Themandrel 1207 is longitudinally coupled to the slickline 150 via theperforating gun assembly 1294 a-d. The setting tool may include a powercharge which is ignitable via an electric signal transmitted from theinterface 200. Combustion of the power charge creates high pressure gaswhich exerts a force on the setting sleeve 1209. Alternatively, ahydraulic pump may be used instead of the power charge.

The adapter 1215 is longitudinally disposed between the setting tool1205 and the frac plug 1225. The adapter 1215 may include a thread-saver1217, a thread cover 1218, an adapter rod 1221, the adapter sleeve 1220,and an adapter ring 1219. Since the thread-saver 1217, thread cover1218, and the adapter rod 1221 will return to the surface, they may bemade from a conventional material, i.e. a metal or alloy, such as steel.The adapter sleeve 1220 and the adapter ring 1219 may be made from anyof the mandrel 1245 materials, discussed above. The thread-saver 1217 islongitudinally coupled to the setting sleeve 1209 with a threadedconnection. The thread cover 1218 is longitudinally coupled to thethread-saver 1217 with a threaded connection. Alternatively, the threadcover 1218 and thread saver 1217 may be integrally formed.

The adapter rod 1221 is longitudinally coupled to the setting mandrel1207 at a first longitudinal end with a threaded connection andlongitudinally coupled to the mandrel 1245 at a second longitudinal endwith one or more shearable members, such as a shear pin 1222 b. Theadapter rod 1221 also shoulders against a first longitudinal end of themandrel 1245 near the second longitudinal end of the adapter rod 1221.The second longitudinal end of the adapter rod 1221 abuts a firstlongitudinal end of the plug 1247. The adapter ring 1219 islongitudinally coupled to the adapter sleeve 1220 at a firstlongitudinal end of the adapter sleeve 1220 with one or more pins 1222a. The adapter ring 1219 is configured so that the thread cover 1218will abut a first longitudinal end of the adapter ring 1219 when thesetting tool 1205 is actuated, thereby transferring longitudinal forcefrom the setting tool 1205 to the adapter ring 1219. A secondlongitudinal end of the adapter sleeve 1220 abuts a first longitudinalend of the first setting ring 1227 a.

To set the frac-plug assembly 1225, the mandrel 1245 is held by theslickline 150, through the setting mandrel 1207 and adapter rod 1247, asa longitudinal force is applied through the setting sleeve 1209 to theadapter sleeve 1220 upon contact of the setting sleeve with the adaptersleeve. The setting force is transferred to the setting rings 1227 a,band then to the slip 1229 a, and then to the first slip cone 1230 a,thereby fracturing the first shear pin 1249 c. The force is thentransferred through the various members 1232 a, 1234 a, 1235 a, 1240,1235 b, 1234 b, and 1232 b to the second slip cone 1230 b, therebyfracturing the second shear pin 1249 c. Alternatively, the shear pins1249 c may fracture simultaneously or in any order. The slips 1229 a,bmove along the tapered surface of the respective cones 1230 a,b andcontact an inner surface of a the casing 40. The longitudinal and radialforces applied to slips 1229 a,b cause the recessed grooves to fractureinto equal segments, permitting the serrations or teeth of the slips1229 a, b to firmly engage the inner surface of the casing 40.

Longitudinal movement of the slip cones 1230 a,b transfers force to theexpansion support rings 1232 a,b. The expansion support rings 1232 a,bmove across the tapered first section of the expansion rings 1234 a,b.As the support rings 1232 a,b move longitudinally, the first section ofthe support rings 1232 a,b expands radially from the mandrel 1245 whilethe wedges hinge radially toward the casing 40. At a pre-determinedforce, the wedges break away or separate from respective first sectionsof the support rings 1232 a,b. The wedges then extend radially outwardto engage the casing 40. The expansion rings 1234 a,b flow and expand asthey are forced across the tapered sections of the respective elementcones 1235 a,b. As the expansion rings 1234 a,b flow and expand, theexpansion rings 1234 a,b fill the gaps or voids between the wedges ofthe respective support rings 1232 a,b.

The growth of the expansion rings 1234 a,b applies a collapse loadthrough the element cones 1235 a,b on the mandrel 1245, which helpsprevent slippage of the frac plug 1225, once activated. The elementcones 1235 a,b then longitudinally compress and radially expand thepacking element 1240 to seal an annulus formed between the mandrel 1245and an inner diameter of the casing 40.

Once the frac plug 1225 has been run-in and set at a first desired depthbelow a first planned perforation interval using the setting tool 1205and adapter 1215, a tensile force is then exerted on the shear pin 1222b sufficient to fracture the shear pin 1222 b. The slickline 150 maythen be retracted, thereby separating the tool string 1200 from the fracplug 1225, adapter sleeve 1220, and adapter ring 1219. Since the adaptersleeve 1220 is left with the frac plug 1225, the radial clearance of thetool string 1200 with the inner surface of the casing 40 is increased,thereby not interfering with subsequent fracturing/stimulationoperations.

The tool sting 1200 is then positioned in the wellbore with perforationcharges 1290 a at the location of the first interval to be perforated.Positioning of the tool string 1200 is readily performed andaccomplished using the casing collar locator. Then the perforationcharges 1294 a are fired to create the first perforation interval,thereby penetrating the casing 40 and cement sheath 44 to establish aflow path with the formation.

After perforating the formation, treatment fluid is pumped andpositively forced to enter the formation via the first perforationinterval and results in the creation of a hydraulic proppant fracture.Near the end of the treatment stage, a quantity of ball sealers,sufficient to seal the first perforation interval, may be injected intothe wellbore. Decentralizers 1214 a,b may be activated, beforecommencement of the treatment or before injection of the ball sealers,to move the tool string 1200 radially into contact with the innersurface of the casing 40 so as not to obstruct the treatment process.Following the injection of the ball sealers, pumping is continued untilthe ball sealers reach and seal the first perforation interval. With thefirst perforation interval sealed by ball sealers, the tool string 1200,may then be repositioned so that the perforation gun 1292 b would beopposite of the second interval 150 b to be treated. The perforation gun1292 b may then be fired to create the second perforation interval,thereby penetrating the casing 40 and cement sheath 44 to establish aflow path with the formation to be treated. The second interval may bethen treated and the operation continued until all of the plannedperforation intervals have been created and the formation(s) treated.

More discussion of operation of the tool string 1200 may be found inU.S. patent application Ser. No. 11/567,102, filed Dec. 5, 2006, whichis hereby incorporated by reference in its entirety.

FIGS. 13A and 13B illustrate an interface 1300, according to anotherembodiment of the present invention. The interface may include acablehead (CH) 1305, a logging tools module 1310, a cablehead/loggingtool (CH/LT) adapter 1310, a controller/power supply (MC+PS) module1320, one or more battery modules 1325 a, b, a memory module 1330, and asafety module 1340. As discussed above for the interface 200, acrossover 1347 (see FIGS. 14D and E) may be used instead of the safetymodule 1340 when non-hazardous wireline tools 1340 are being deployedwith the interface 1300. The wireline tools 1340 may include one or moreof any of the wireline tools 100, 700, 800, 1000-1200. As with theinterface 200, the modules may be in data and electrical communicationvia an ITB 1350-1395. Also as with the interface 200, each of themodules may be connected using the field joint 290. The logging toolsmodule 1310 may be identical to the logging tools module 900. The safetymodule 1335 may be identical to the safety module 600. The batterymodules 1325 a, b may each be identical to the battery module 400. Thememory module 1330 may include a memory unit, a controller, and an ITBinterface.

As compared to the interface 200, the main controller and power supplymodules have been combined into one module 1320. The combined MC+PSmodule 1320 may include the main controller, the power switch andmonitor, the FP interface, the controller power supply 1320 a, the FPpower supply 1320 b, and the FP relay. The main controller may besimilar to the main controller of the interface 200 with the addition ofan interface to the FP power supply so that it may perform the duties ofboth main controller and power supply controller of the interface 200.The main controller need not include the pressure sensor, temperaturesensor, and CCL as these may be located in the cablehead 1305. Thecablehead 1305 may now include a processor, an ITB interface, andinterfaces for the sensors and may communicate with the main controllervia the ITB. Further, to download data from the main controller, themain controller field joint 290 may be directly plugged into as the pins1380 b, 1385 b, 1390 b, and 1395 b are USB compatible. A simpleUSB/field joint adapter allows for connection to a standard USB device.The memory module 1330 includes a field joint 290 with similarcapability.

Also as compared to the interface 200, the MC+PS module 1320 may onlyinclude the FP power supply to alternatively power the logging tools orthe wireline tools. Having only one FP power supply reduces the requiredsize of the MC+PS module and thus the interface 1300. Further, asdiscussed below, at least some of the intended configurations of theinterface do not include both the logging tools module and wirelinetools so that two separate power supplies are not needed. For theconfigurations that do include both wireline tools and logging tools, itmay not be necessary to power both simultaneously. Additionally, an LTpower supply or a second FP power supply may be added to the MC+PSmodule 1320.

FIGS. 14A-E illustrate configurations 1400 a-e of the interface 1300intended for specific operations. Configurations 1400 a, b are intendedfor gage runs. The gage run configurations 1400 a, b include thecablehead 1305, the CH/LT adapter 1315, the MC+PS module 1320, one ofthe battery modules 1325 a, and a bull plug 1345. The gage runconfiguration 1400 b further includes a gamma ray module 1310. Theinternal memory of the main controller may be sufficient to store thegamma ray data or the memory module 1330 may be employed.

A gage run is usually performed before a particular service operation iscarried out. For example, given a FP operation, the gage run may beconducted by lowering the configuration 1400 a of the interface 1300into the wellbore to a depth below the stuck point. The main controllerdetects the trigger event and activates the CCL and may also activatethe pressure and/or temperature gages. The interface 1400 a is raised tothe surface while the main controller records the time at which eachcollar of the drill string is detected. The drill string may be held ina neutral position during the gage run or may be unsupported from thesurface. The gage run continues until the interface reaches the surfacewhere the data may be downloaded from the main controller (the data maybe stored in the internal memory of the main controller). The data maythen be correlated to surface recorded data (i.e., length of unspooledslickline 150 vs. time) to generate a collar log. The collar log maythen be used to program a number of collars as the trigger event for themain controller for the subsequent service operation.

The gage run configuration 1400 b allows for pattern recognitiontechnology (PRT) to be implemented. Using a CCL to determine depth maynot be as accurate as desired. Improper or inaccurate measurements ofthe length of the drill string may take place due to inconsistentlengths of collars and drill string/casing, pipe stretch, pipetabulation errors, etc., resulting in erroneous location of each drillstring/casing string collar. Thus, the interface 1300 and wireline tools1340 may be positioned at the wrong depth of the wellbore based on acollar log.

To perform a PRT gage run, the interface 1300 is lowered into thewellbore to a predetermined depth. The main controller detects thetrigger event and activates the gamma ray tool. The interface 1300 isthen raised toward the surface, for example, at a rate of approximately5 meters per minute, to record gamma counts as the gamma ray tool passesby differing lithologies. Once the interface reaches the surface, thegamma ray data may be downloaded from the main controller. A log is thengenerated by merging the recorded surface depth/time records with thedownhole gamma count record. The log is then compared to a previouslyproduced well log (e.g., open-hole gamma-ray log) and correlated to thesame marker formation. As the open hole gamma-ray log is consideredcorrect, a depth position adjustment, if necessary, is calculated basedon the comparison of the gamma log to the open hole gamma-ray log. Oncethe log data has been analyzed, a gamma pattern may be programmed intothe main controller as the trigger event for a subsequent operation.Alternatively, a neutron tool may be used instead of a gamma ray tool.

Configuration 1400 c is intended for hazardous service. The hazardousservice configuration 1400 a, b includes the cablehead 1305, the CH/LTadapter 1315, the MC+PS module 1320, one of the battery modules 1325 a,the safety module 1335, and a hazardous wireline tool 1340. Thehazardous wireline tool 1340 may include the radial cutting torch 800,the perforation tool 1100, the tool string 1200, a stringshot, a jetcutter, or a chemical cutter.

Configuration 1400 d is intended for pipe intervention. The pipeintervention configuration 1400 d includes the cablehead 1305, the CH/LTadapter 1315, the MC+PS module 1320, the battery modules 1325 a, b, thecrossover 1347, and a wireline tool 1340. The wireline tool 1340 mayinclude one or more of the FPT 100, the cutting tool 700, the toolstring 1000, and the setting tool 1205 and the frac plug 1225.

Configuration 1400 e is intended for logging. The logging configuration1400 e includes the cablehead 1305, one or more of the logging tools1310, the CH/LT adapter 1315, the MC+PS module 1320, one of the batterymodules 1325 a, and the memory module 1330.

Another alternative embodiment of the interface is discussed in U.S.Pat. No. 6,945,330, which is incorporated by reference in its entirety.Another alternative embodiment of the interface is discussed in U.S.Pat. App. Pub. No. 2005/0269106, which is incorporated by reference inits entirety. Another alternative embodiment of the interface isdiscussed in U.S. Pat. No. 6,736,210, which is incorporated by referencein its entirety. Another alternative embodiment of the interface isdiscussed in U.S. Pat. App. Pub. No. 2005/0240351, which is incorporatedby reference in its entirety.

FIG. 15A illustrates another wireline tool string 1500 a that may bedeployed using one of the interfaces 200, 1300, according to analternative embodiment of the present invention. The pickup-unloader1000 c has been removed and replaced with another deflation tool, suchas an electronic shut-in tool (ESIT) 1510. To facilitate placement ofthe ESIT, the plug 1000 e has been replaced by a packer 1505. The ESIT1510 may be connected to a lower portion of the inflatable packer 1505and in fluid communication therewith. The packer may be identical to theplug 1000 e except for replacement of the nose 1099 with a coupling forconnection to the ESIT 1505. Additionally, the pickup unloader 1000 cmay be used in the string 1500 a as a backup for the ESIT 1510.

The ESIT 1510 is illustrated in FIG. 8 of the '154 application. The ESIT1510 may include an upper valve housing, a valve sleeve, a lower valvehousing, a piston housing, a valve operator, a shear pin, a top sub, ahead retainer, a thrust bearing, a boss, a nut connector, a drivehousing, a motor crossover, a lower thrust bearing, a thrust sub, agrease plug, a motor housing, a motor bracket, a coupling, a couplinglink, a shaft coupling, a battery crossover, a battery housing, a bottomsub, a battery pack, a drive shaft, an electric motor and electronicsassembly, a nut, a filter, a connector, one or more O-rings, a wearstrip, a longitudinal pressure seal, a cap screw, a set screw, a greasefitting, and a back up ring.

The electronics may include a memory and a controller having anysuitable control circuitry, such as any combination of microprocessors,crystal oscillators and solid state logic circuits. The controller mayinclude any suitable interface circuitry such as any combination ofmultiplexing circuits, signal conditioning circuits (filters, amplifiercircuits, etc.), and analog to digital (A/D) converter circuits. In use,the ESIT 1510 may be preprogrammed with the desired open and closeintervals, for example, open for 30 minutes and close for 12 hours. Whenthe ESIT 1510 is open, the packer 1505 will be allowed to deflate. Whenthe ESIT 1510 is closed, the packer 1505 will be allowed to inflate, forexample, by the inflation tool 1000 a. The preprogrammed intervals willallow the tool string 1500 a to be repositioned at another zone fortesting.

The valve sleeve is longitudinally movable relative to the housings byoperation of the motor. The valve sleeve is movable between a closedposition where a wall of the valve sleeve covers one or more flow portsformed through a wall of the upper valve housing and an open positionwhere the flow ports provide fluid communication between the packingelement annulus 1089 and the wellbore. A shaft of the motor isrotationally coupled to the drive shaft via the couplings. A portion ofthe drive shaft has a thread formed on an outer surface thereof. The nutis engaged with the threaded portion of the drive shaft. Rotation of thedrive shaft by the motor translates the nut longitudinally. The nut islongitudinally coupled to the valve operator. The valve operator has oneor more slots formed through a wall thereof. A respective head retaineris disposed through each of the slots. Each head retainer islongitudinally coupled to the housing assembly. In the closed position,each head retainer engages an end of the slot. The valve operator islongitudinally coupled to the valve sleeve. Thus, rotation of the motorshaft moves the valve sleeve longitudinally relative to the housingassembly from the closed position to the open position where the valvesleeve openings are in fluid communication with a bore of the uppervalve housing and thus the packer. In the open position, each headretainer engages the other end of the respective slot.

A bore formed through the valve sleeve is in fluid communication withthe upper valve housing bore. The valve sleeve is also in filtered fluidcommunication with a bore formed through the piston housing. One or moreports are formed through a wall of the piston housing. The ports providefluid communication between the piston housing bore and a bore formedthrough the valve operator. The slots formed through the valve operatorprovide fluid communication between the valve operator bore and aclearance defined between the valve operator and the top sub. Theclearance provides fluid communication between the valve operator boreand a chamber formed between valve sleeve and the valve housing. Thisfluid path keeps a first longitudinal end of the valve sleeve equalizedwith a second end of the valve sleeve so that the motor does not have toovercome fluid force. Alternatively, the ESIT 1510 may be incommunication with the FP Power Supply for receiving power and/orcontrol signals.

FIG. 15B illustrates another wireline tool string 1500 b that may bedeployed using one of the interfaces 200, 1300, according to analternative embodiment of the present invention. The tool string 1500 bincludes the packer 1505 and the plug 1000 e separated by a spacer pipe1515. Alternatively, the plug may be replaced by a second packer so thatthe ESIT 1510 may be used instead of the pickup unloader 1000 d. In use,the packer and plug may be actuated to straddle a zone of interest.During testing, the zone(s) above the packer 1505 may be monitored forthe production flow. The zone between the plug and the packer may bemonitored for pressure changes caused by flowing the zone above thepacker. The collected pressure data may be used to further determine thepotential of the formation. Additionally, the zones may be monitored fortemperature, fluid density, or other desired parameters.

FIG. 15C illustrates another wireline tool string 1500 c that may bedeployed using one of the interfaces 200, 1300, according to analternative embodiment of the present invention. The tool string 1500 cincludes a production logging tester (PLT) 1520, two ESITs 1510 a, b,and two instrumentation subs 1525 a, b. The PLT 1005 includes a flowmeter. The flow meter may be a simple single phase meter or a multiphase(i.e., gas, oil, and water) meter. The flow meter may be as simple as aspinner or as complex as a Venturi with a gamma ray tool and pressureand temperature sensors to measure flow rates of individual phases. Theinstrumentation subs 1525 a, b may each include a pressure sensor and atemperature sensor in fluid communication with the wellbore. Theinstrumentation subs 1525 a, b may also include sensors for measuringother wellbore parameters, such as fluid density, flow rate, and/or flowhold up. For the more complex flow meters, the instrumentation sub 1525a may be omitted if it is redundant. One of the instrumentation subs1525 a, b may also include sensors (discussed above) for monitoring toolstring performance. The instrumentation sub 1525 b is optional.

The tool string 1500 c may straddle and test each of the zonesindividually. For example, the packers 1505 a, b may be inflatedadjacent one of the zones to straddle the zone. The ESIT 1505 a portopens to allow production fluid into a bypass path in fluidcommunication with the PLT. The production fluid travels along thebypass path to the PLT 1005 which measures the flow rate of the fluid.The fluid exits the PLT 1005 and comingles with the fluid from any zonesabove the zone being tested. The data from the PLT 1005 may be stored inan internal memory unit or transmitted to the main controller forstorage in the main controller memory or the memory unit/module. Thepackers may then be deflated using the second ESIT 1510 b. The toolstring 1500 c may then be moved to the next zone of interest and thesequence repeated.

The tool string 1500 c provides for collection of the flow test data inthe wellbore 15 instead of at the surface. In this manner, any transientflow pattern (i.e., slugging) may be measured before the flow patternchanges while flowing to the surface.

Additionally, any of the tool strings 1000, 1500 a-c may include aperforation gun. The perforation gun may be used after testing of thezones 100 a-c to further perforate any of the zones 100 a-c.Additionally, the string 200 may be moved to a depth of a new zone andthe perforation gun used to create the new zone in the same trip thatthe zones 100 a-c are tested. Alternatively, the perforation gun may beused to create any one of the zones 100 a-c prior to testing.

While the foregoing is directed to embodiments of the present invention,other and further embodiments of the invention may be devised withoutdeparting from the basic scope thereof, and the scope thereof isdetermined by the claims that follow.

1. A method of determining a free point of a tubular string stuck in awellbore, comprising acts of: deploying a tool string in the stucktubular string with a non-electric string, the tool string comprising afree point tool and an interface, the interface comprising a battery, acontroller, and a memory unit; activating the free point tool by thecontroller, wherein the free point tool contacts an inner surface of thestuck tubular string; applying a tensile force and/or torque to thestuck tubular string; measuring a response of the tubular string withthe free point tool; storing the free point measurement in the memoryunit; retrieving the tool string to the surface; downloading the freepoint measurement from the memory unit; and determining the free point.2. The method of claim 1, further comprising detecting a trigger eventby the controller, wherein the controller activates the free point toolin response to detecting the trigger event.
 3. The method of claim 1,further comprising removing the free point tool from the tool string;adding a cutting tool to the tool string; redeploying the tool stringwith the non-electric string to the free point; and activating thecutting tool by the controller, thereby severing a free portion of thetubular string from a stuck portion of the tubular string.
 4. The methodof claim 1, wherein the wellbore intersects a formation, the interfacefurther comprises a logging tool, and the method further compriseslogging the formation.
 5. The tool string of claim 3, wherein theinterface is modular, and the interface further comprises a busextending along the interface and operable to provide data and powercommunication among the modules.
 6. The tool string of claim 3, whereinthe interface further comprises an adjustable power supply.
 7. The toolstring of claim 3, wherein the interface further comprises a memoryunit.
 8. The tool string of claim 3, wherein the interface furthercomprises a pressure sensor and a temperature sensor.
 9. The tool stringof claim 3, wherein the interface further comprises casing collarlocator and a tension senor.
 10. The tool string of claim 3, furthercomprising a cutting tool, wherein the interface further comprises asafety operable to isolate the controller from the cutting tool untilthe safety detects a condition indicative of the tool string beingdisposed in the wellbore.
 11. The tool string of claim 3, wherein theinterface further comprises a logging tool.
 12. A tool string fordetermining a free point of a tubular stuck in a wellbore, comprising: afree point tool, comprising: a longitudinal strain gage and/or atorsional strain gage; first and second anchors operable tolongitudinally and rotationally couple the strain gages to the stucktubular in an extended position; an electric motor operable to extendand/or retract the anchors; and an interface, comprising: a battery; anda controller operable to supply electricity from the battery to the freepoint tool, wherein the tool string is tubular.
 13. A tool string foruse in wellbore, comprising: a wireline tool; a battery module; acontroller module operable to supply electricity from the battery to thewireline tool; a bus extending through the modules and operable toprovide data and power communication among the modules; and a safetymodule operable to isolate the controller module from the wireline tooluntil the safety module detects a condition indicative of the toolstring being disposed in the wellbore, wherein the tool string istubular.
 14. A method of determining a free point of a tubular stringstuck in a wellbore, comprising acts of: deploying a tool string in thestuck tubular string with a non-electric string, the tool stringcomprising a free point tool and an interface, the interface comprisinga battery and a controller; activating the free point tool by thecontroller, wherein the free point tool contacts an inner surface of thestuck tubular string; applying a tensile force and/or torque to thestuck tubular string; measuring a response of the tubular string withthe free point tool; disengaging the free point tool from the stucktubular by the controller; moving the free point tool to anotherlocation in the stuck tubular; and repeating the activating, applying,and measuring acts.
 15. The method of claim 14, wherein the tool stringfurther comprises a cutting tool, and the method further comprisesdetermining the free point by the controller; and operating the cuttingtool by the controller, thereby severing a free portion of the tubularstring from a stuck portion of the tubular string.
 16. A method ofdetermining a free point of a tubular string stuck in a wellbore,comprising acts of: deploying a tool string in the stuck tubular stringwith a non-electric string, the tool string comprising a free point tooland an interface, the interface comprising a battery and a controller;activating the free point tool by the controller, wherein the free pointtool contacts an inner surface of the stuck tubular string; applying atensile force and/or torque to the stuck tubular string; and measuring aresponse of the tubular string with the free point tool, wherein: thewellbore intersects a formation, the interface further comprises alogging tool, and the method further comprises logging the formation.